In unconventional resource plays and fields with structural or stratigraphic complexities, reliable geosteering of horizontal laterals is essential to economic success. Each foot drilled out of zone represents a potential loss of production revenue. Using real-time logging-while-drilling (LWD) data can reduce directional drilling risk. However, conventional bed boundary imaging tools are typically located far behind the drill bit. This creates a significant lag in response time and increases the odds of exiting the target interval.
The recent introduction of an at-bit inclination, gamma ray, and imaging technology has enabled Fidelity Exploration & Production to optimize well placement in a target formation of the Paradox Basin in Utah—despite unexpected faults and local changes in formation dip that were not clearly resolved with seismic data.
The Geological Challenge
During the Pennsylvanian period, the Paradox Basin was rapidly subsiding and filling with thick, cyclic sequences of marine carbonates, evaporates, silts, and shales. Relatively thin, reservoir-quality clastic and carbonate formations became interbedded within organic-rich shales, surrounded by thick salt deposits. Salt above and below these self-sourced oil and natural gas reservoirs provides critical sealing capacity, while preserving overpressures generated during hydrocarbon maturation. However, the thicknesses of potential reservoirs vary as a result of syndepositional faulting and subsequent salt movement, dissolution, and collapse. Many exhibit open, near-vertical fractures controlled by regional tectonics and local folding because of salt flows over anticlines and underlying fault blocks.
Local thickness variations, folding, and subseismic faulting of Paradox reservoirs have presented significant challenges to operators. One target interval, a dolomite-silica silt reservoir enclosed in a fractured and overpressured shale formation, averages 40-ft thickness in southwestern Utah.
Drilling activity there has undergone two distinct phases, with varying degrees of success. The first phase, from the 1960s through the early 1980s, included the drilling and completion of almost a dozen vertical wells. One well was an economic success, producing more than 1 million bbl of oil and establishing the formation’s potential. Horizontal drilling, introduced in the early 1990s, increased the probability of encountering natural fractures that influence production. Roughly half of these wells produced commercial oil, including one that has yielded more than 600,000 bbl to date.
When Fidelity began exploratory drilling in the area, targeting this thin carbonate interval, some wells encountered unanticipated normal and reverse faults, as well as sudden formation dip changes often caused by localized folding. Conventional measurement-while-drilling (MWD) gamma-only logging configurations place the measurement tools by 35 ft to 65 ft behind the bit. Given the structural complexities of the play, traditional technology could not provide sufficiently rapid reaction time to stay within the target zone. To meet the horizontal geosteering challenge, Fidelity selected PathFinder Services to deliver the real-time at-bit gamma ray imaging technology, commercialized in March 2012. Previously, the system had been successfully field tested in coalbed methane, heavy oil, and shale plays in North America and Australia.
New Geosteering Technology
The iPZIG at-bit inclination, gamma ray, and imaging system is the industry’s first gamma imaging tool positioned directly behind the bit. Developed specifically for unconventional oil and gas plays and high-efficiency drilling applications, the technology ensures greater directional control and accuracy than conventional technologies. In addition to total natural gamma ray measurements, it provides at-bit gamma ray imaging, dynamic inclination data, revolutions per minute, and temperature. Using the real-time data, drilling engineers and geologists can quickly identify changes in lithology and orientation of the bottomhole assembly (BHA) to maintain well placement within the target zone, or to steer back into it sooner if the zone is lost.
Combining the directional drilling and MWD/LWD capabilities with real-time forward modeling software accurately and cost-effectively optimizes well placement and trajectory while drilling. Correlating petrophysical log data from offset wells with the current directional well plan and structural information, the system produces a predicted earth model. While drilling, at-bit gamma ray imaging data continuously update the model to compute the dip of bedding planes and determine the position of the well path in the formation, allowing time to implement critical directional corrections. Having the “closest-to-the-bit” sensor, the system provides earlier bed boundary detection and facilitates more rapid geosteering adjustments, thereby maximizing productive reservoir contact even in the presence of complex geology.
Case Study: Fractured Dolomite Reservoir
Given the geologic uncertainties of the highly dynamic structure in the Paradox Basin, Fidelity decided to use the new at-bit inclination and gamma ray imaging technology for a series of horizontal appraisal wells drilled in 2012. The ideal section of the target consists of a fractured 12-ft dolomite bounded by two secondary intervals. In part because of a lack of unexpected faulting, the first four wells successfully tracked the productive zone for almost 100 percent of the lateral section. However, the fifth well proved much more challenging. Seismic data, which had helped steer previous wells, provided inconclusive resolution of the formation in this area. Without real-time, at-bit inclination measurements and gamma ray imaging (Fig. 1), it would have been difficult to drill a successful well.
While drilling the pilot hole, the target formation came in approximately 250 ft shallower than expected, which created the initial drilling challenge. Uncertainties in projecting the target formation’s location continued to present challenges to the use of conventional MWD gamma ray correlations in building the curve through large sections of salt. Upon successfully landing the curve to position the wellbore in the target zone, a trip was made to add at-bit imaging technology to the lateral BHA (Fig. 2).
Initial formation dip angles had been projected from 2° updip to 3° downdip. However, after landing in the target interval, dips calculated from at-bit gamma imaging averaged 5° updip, rapidly rising to more than 9° over a span of 560 ft measured depth (MD). At that point, the wellbore crossed a large, unexpected fault, exiting the dolomite and fractured shale formation and entering an undifferentiated Paradox salt. The throw, amplitude, and direction of the fault were unknown. A normal fault with downward throw of more than 60 ft would place the wellbore in the salt above the shale. In the case of a reverse fault, the well would be in the salt below the shale. Suspecting that the throw had been downward, the drilling team decided to drill ahead, dropping angle from 100° to 90° and back to 93°, until logging responses and cuttings analysis could identify either the top or base of the formation.
After confirming that the wellbore was in the salt above the formation, the team decided to back up and initiate an openhole sidetrack with the aid of at-bit inclination data to reposition the wellbore back within the primary target zone. Measuring an inclination change of more than 4° down, the system confirmed that the sidetrack had been achieved. This saved valuable rig time because there was no need for a trip to change the drilling assembly. The sidetrack successfully re-entered the top of the reservoir after 560 ft MD of drilling.
An additional 2,000 ft MD of lateral was drilled before calling total depth. Over this interval, formation dips changed a number of times because of localized folding and additional near-vertical faults. The fault locations were interpreted based on real-time gamma ray image logs. The first fault, with an estimated 7 ft displacement, positioned the wellbore out of the ideal target zone. While drilling down, the wellbore crossed an additional fault with an estimated 14-ft throw and re-entered the dolomite. Subsequently, the lateral crossed the upper boundary of the target interval again, because of another change in formation dip.
In each of these situations, at-bit logging measurements reduced the time required to recognize the formation change. An apparent local dip was calculated in real time from bedding features interpreted in at-bit gamma images, thus enabling a quick response from the drilling team. The well trajectory was revised in each case, and the wellbore repositioned within the primary target zone.
Conclusion
Based on real-time measurements and interpretations from this new at-bit inclination and gamma ray imaging system, 85% of the lateral in Fidelity’s fifth horizontal well remained within the targeted interval. This was an exceptional outcome, given the geological challenges. Because of the success of recent appraisal and development drilling, Fidelity plans to deploy the same technology and pay zone geosteering services in future wells in the Paradox Basin play.